To develop oil and gas resources, the drilling industry employs drill bits to bore the well. Traditionally, the long drill string is rotated at the surface location to drive the drill bit. The drill string is rotated either by the rotary table or a direct drive system, called the top drive. Alternatively, the drill bit may be rotatably driven by the employment of a downhole mud motor. Factors strongly influencing the rate of drilling the formation include the axial load and the torque by the bit on the formation, called WOB (weight-on-bit) and TOB (torque-on-bit) respectively.
The drill string also carries many tools and instruments, mostly downhole near the bit, particularly since the development of MWD (measurement-while-drilling) technology. These MWD subs are capable of measuring various drilling and formation property information, manipulating the information into compacted data, and transferring this data to the surface through various means, most typical of them is the mud-pulse telemetry. This transmitted data, while drilling or during tripping, provides great benefits by improving the drilling trajectory and drilling condition monitoring, and also by providing improved formation physical property evaluation when compared to the more traditional wireline logging, since the formation is freshly drilled and not as altered by the invasion of the drilling mud.
Due to various reasons such as misalignment, mass imbalance, inhomogeneity in the physical properties of the rock drilled, side-cutting of the drill bit, and/or the drill string's excitation due to contacts with the borehole wall during drilling and tripping, a drill string will exhibit dynamic vibrations which may have a combination of the following modes: axial, torsional and lateral bending vibrations. The lateral bending vibration under rotation of the shaft results in a "whirling" motion of the center of the drill string's cross-section.
Severe vibrations in such systems are very undesirable for many reasons. First, severe torsional and axial vibrations are transmitted to the surface, and may adversely affect the operating safety. Secondly, it will increase the repair and maintenance cost of the drill pipes, the downhole tools and subs, and may adversely affect their useful lives. Thirdly, it may adversely impact on the drilling efficiency leading to increased drilling cost. Fourthly, it may adversely impact on the quality and the trajectory of the well bore, resulting in increased risk of drilling crooked holes leading to stuck pipes and major drilling difficulties. This aspect is particularly important in directional (including horizontal and extended reach) wells. And finally, it may adversely affect the accuracy of the data measured by the downhole subs, complicating their interpretation, reducing and in some cases destroying their usefulness.
For these reasons, the drilling industry has had long-standing interest in the dynamic behavior of the drill string, and has carried out research through mathematical modeling and through measurements. The measurements have been carried out both at the surface and downhole. The pace of study on drill string dynamics has increased tremendously in the past ten years, coinciding more or less with the development of MWD technology. The current trend is toward intelligent monitoring of the downhole dynamic behavior of the drill string through downhole measurements, processing and data compaction, and appropriate interpretations.
To achieve these objectives, it is essential for the industry to perform the following tasks: (1) Place effective and sufficient sensors at desirable locations in the bottomhole assembly and/or at the surface; (2) Properly sample the data and correct for any significant errors in order to arrive at correct desired physical quantities describing the dynamic motion of the assembly; (3) Develop suitable analysis and recognition software models/routines that will enable downhole (and/or surface) processing of the above mentioned data; (4) Generate significant compacted downhole data describing key dynamic parameters that can be transmitted in real-time to the surface; and (5) Using the key transmitted downhole data or the interpreted surface data, modify the drilling program, if necessary, to ameliorate the downhole dynamics of the assembly, or to use this data for other modeling purposes.
In particular, the present invention emphasizes the measurements of the following parameters: (a) the torque and/or rotating speed (RPM), whether time-averaged or instantaneous; and (b) the whirling motion (describing the trajectory of the center of the shaft within the plane transverse to the axis of the shaft), which will induce bending stresses in the drill string.
The current measurement technology is, essentially, based on "separately" measuring either one or both of the above quantities. This is to say, when torque and/or RPM are measured, we assume the shaft does not whirl. Likewise, when shaft whirl is measured, we assume the shaft to be rotating with constant RPM and torque. In some situations, where vibration is mild, these may be reasonably good assumptions.
In the more general situations, a drill string will exhibit both rotating speed (and torque) fluctuations as well as whirling. Under such circumstances, two scenarios may happen: (a) The current methods may result in significant errors in the measured data, which may lead to erroneous interpretations of the observed behavior of the drill string; or (b) The current methods may result in insufficient information for the proper inference of the needed data describing the complex motion.
Various U.S. patents have issued in the recent past concerning the development of measurement-while-drilling (MWD) technology. Originally, U.S. Pat. No. 4,662,458, issued on May 5, 1987 to the present inventor. This patent describes a method and apparatus for obtaining complete loading on a drill bit at an end of a drill string in a borehole. At least three rosette strain gages were uniformly disposed on an instrument sub to measure torque and axial force on the sub, two bending moments in mutually perpendicular directions, and two shear forces in mutually perpendicular directions.
U.S. Pat. No. 4,773,263, issued on Sep. 27, 1988, to Lesage et al. teaches a method of analyzing vibrations from a drill bit in a borehole. In this patent, the frequency distribution spectrum of a vibrational quantity is measured from the impact of cutter teeth of the bottom of a bore. Spectra are obtained from the product of signals indicative of torque and torsional acceleration. Tooth wear is then indicated by the shift upwardly in frequency of peaks in the spectra.
U.S. Pat. No. 4,903,245, issued on Feb. 20, 1990, to Close et al. describes an apparatus for monitoring vibration of a bottom hole assembly which includes at least one accelerometer mounted in the bottom hole assembly to generate data in the form of electrical signals corresponding to the acceleration experienced by the assembly. The computer in the assembly is programmed to collect data from the accelerometers and compute magnitude of the assembly acceleration. Means are included for selecting from the collected data a value which exceeds a preset limit.
U.S. Pat. No. 4,958,517, issued on Sep. 25, 1990, to R. Maron shows an apparatus for measuring weight, torque, and side force (bending) on a drill bit. This apparatus includes radial holes which do not pass completely through the wall of the drill collar sub, but instead, pass only partially through the wall of the drill collar sub. Strain gages are located in the partial radial openings. These strain gages measure each of the three parameters of weight, torque and bending. For torque and bending measurements, the strain gages are arranged with symmetry of position between diammetrically opposed holes.
U.S. Pat. No. 5,058,077, issued on Oct. 15, 1991, to J. R. Twist provides a technique for generating a corrected well log. Sensor signals are generated at time intervals of less than one-half the period of the highest frequency of the periodic movement of the drill collar. Discrete sensor signals are averaged to generate an average sensor signal as a function of borehole depth. Discrete sensor signals are also are also recorded to generate a time-varying sensor signal profile, the magnitude of frequency components of the time-varying sensor signal profile is determined, and the average sensor signal is corrected as a function of the determined magnitude of the frequency components. The corrected sensor signals are preferably recorded as a function of borehole depth to generate a corrected well log.
U.S. Pat. No. 5,141,061, issued on Aug. 25, 1992, to H. Henneuse teaches a device for the auditory and/or visual representation of mechanical phenomena in the interaction between a drilling tool and the rock being drilled. A mechanism is provided for picking up a vibratory signal representing the vibration of the tool at the cutting face. An accelerometric sensor is provided at a specific point on the drilling stem. Processing equipment is provided for filtering the signal and the frequency band of 10 to 200 Hz.
U.S. Pat. No. 5,159,577, issued on Oct. 27, 1992, to J. R. Twist shows a technique for correcting signals from a downhole sensor on a drill collar eccentrically rotating within a borehole. The corrected sensor signal is used to generate a well log which more accurately represents the conditions which the sensor would have generated had the tool been rotating such that the spacing between the sensor and the borehole wall remains constant. The sensor signals are generated at time intervals of less than half the period of the rotation of the drill collar. The frequency components of the time-varying sensor signals are plotted, and the frequency component attributable to the eccentric rotation between the drill collar and the borehole may be determined. The techniques of this invention are used to determine actual rotational speed of the drill collar and the spacing between the sensor and the wall. This technique is used to determine a whirling condition in real time and to alter drilling parameters in response thereto.
U.S. Pat. No. 5,175,429, issued on Dec. 29, 1992 to Hall, Jr. et al. teaches a device for increasing the accuracy of measurement-while-drilling systems. A secondary measurement system is provided for determining the tool displacement from the borehole wall for calculated compensation of measurement data.
This aforestated technology is inadequate in determining the whirl motion. For example, U.S. Pat. No. 4,903,245 includes three eccentrically-mounted accelerometers along different axis, and two-axes magnetometers, in addition to the measurements of two-axes bending moments, the axial force, and the torsional moment.
It is an object of the present invention to provide an apparatus and method that is suitable for measuring kinematic and force resultant measurements.
It is another object of the present invention to provide an method and apparatus that allows calculations to be carried out which take into account the coexistence of both the torsional vibration and the whirling motion of the drill string.
It is a further object of the present invention to provide an method and apparatus that includes measurements required to calibrate for various sensor elements.
It is still another object of the present invention to provide an method and apparatus whereby measurement of rotational movement and whirling behavior of a drill string can be used for optimally controlling the speed and operation of the drill string.
These and other objects and advantages of the present invention will become apparent from a reading of the attached specification and appended claims.